In geological exploration it is desirable to obtain information regarding the various formations and structures that exist beneath the Earth's surface. Such information may include determining geological strata, density, porosity, composition, etc. This information may then be used to generate a representation of the subsurface basin using the obtained data to predict the location of hydrocarbon reserves and aid in the extraction of hydrocarbons.
A general objective of seismic processing is to image subsurface reflectors. In a general prospecting operation, during a seismic survey, seismic energy is generated by a source and travels as body waves into subsurface regions to reflectors, and then returns to receivers (e.g., geophones). The reflected energy received may then be processed to determine a representation of the subsurface region (e.g., via imaging) to, for example, analyze the location of hydrocarbon reserves.
Three-dimensional (3D) seismic survey techniques are well-known in the art. In general, seismic monitor data (e.g., the above-mentioned reflected energy collected by a receiver, such as a geophone) is acquired for a target area (or “field”) that is of interest, and such seismic monitor data is processed to form a representation of the subsurface region that is the target area. The representation of the subsurface may take any of various different forms, including an image of the subsurface at various depths. Such representation of the subsurface may identify the geological formations (e.g., location, shape, etc. of different geological materials/objects), including hydrocarbon bearing underground reservoirs of fluids (e.g., oil, gas, water). Conventional 3D seismic surveys include three dimensions relating to the spatial characteristics of the subsurface formation. Generally, two dimensions correspond to horizontal length dimensions, and the third dimension relates to depth in the subsurface formation, which can be represented by a length coordinate (or by a time coordinate, such as the two-way travel time of a seismic wave from surface to a certain depth and back).
Seismic surveying techniques generally investigate the subsurface formation by generating seismic waves that travel through the subsurface formation, and measuring the time the waves need to travel between one or more seismic sources and one or more seismic receivers. The travel time of a seismic wave is dependent on the length of the path traversed, and the velocity of the wave along the path. 3D seismic surveying is commonly employed when analyzing a target field for potential drilling to extract fluids (e.g., for determining whether and/or where in the target field to drill). As discussed further herein, such 3D seismic surveying has traditionally been computationally intensive, expensive, and have involved significant time to produce.
Time-lapse seismic surveying is increasingly used for studying of subsurface formations. It is applied for monitoring of hydrocarbon bearing underground reservoirs, in particular to follow the effects resulting from producing (i.e., “extracting”) reservoir fluids (e.g., oil, gas, water) through a well to the surface.
In time-lapse seismic surveying, seismic data is acquired at two or more points in time. Time is therefore an additional parameter with regard to conventional seismic surveying. This is useful in studying the changes in seismic properties of the subsurface as a function of time due to, for example, spatial and temporal variation in fluid saturation, pressure, temperature, and/or other seismic properties. Conventionally, such time-lapse seismic surveying involves performing the above-mentioned 3D surveying at different points in time. Thus, time-lapse seismic surveying is also referred to as 4-dimensional (4D) seismic surveying, wherein time between seismic data acquisitions represents a fourth data dimension. As in the above-mentioned 3D surveying, the three other dimensions relate to the spatial characteristics of the earth formation. The time span between the first and the second point in time at which seismic data are acquired may be several years. Conventionally, one normally tries to acquire the first and second seismic data sets in a similar manner, so that the data sets are easier to compare.
Time-lapse (or “4D”) seismic surveying has become a common tool for monitoring changes in producing hydrocarbon reservoirs. The information about changes in reservoir fluid distribution and pore pressure provided by time-lapse surveys is useful in making decisions in reservoir management. Decisions affected by time-lapse seismic surveying include placement of infill wells and control of production and injection rates to maximize oil recovery efficiency, as examples.
The typical implementation of time-lapse seismic involves collecting a sequence of 3D seismic surveys over a producing reservoir, and using the representations (e.g., images) generated from the recorded seismic data to infer changes in reservoir conditions over time. For economic reasons, some time-lapse surveys have been collected using conventional marine streamer acquisition, where a boat sails a grid of lines over the reservoir, continuously activating seismic sources and recording data using receivers in long streamers towed behind the boat. However, the method has also been implemented using receivers placed on the sea floor, in bore-holes, and, for onshore fields, using conventional 3D land acquisition methods.
The first survey in the time-lapse sequence, commonly called the “base survey,” is ideally acquired before production starts. The processed image generated from the base survey measures the initial seismic response of the reservoir. One or more later surveys, called “monitor surveys,” are acquired at time intervals that depend on the expected dynamic properties (e.g., fluid distribution and pressure) of the reservoir; e.g., one to three year intervals are typical.
The reservoir image generated from a monitor survey is different from the base survey image. Some of this difference is due to changes in dynamic reservoir properties; and some is due to a variety of other factors not related to reservoir changes. Differences between base and monitor images that are not associated with reservoir changes, commonly called “non-repeatability”, can mask the differences that indicate reservoir changes. Minimizing non-repeatability is one of the objectives of time-lapse acquisition and processing for seismic or other data types, such as electromagnetic and/or magnetic data.
Acquiring and processing a full 3D monitor survey is time-consuming and expensive. For instance, with seismic data, the time required to acquire, process and interpret a given survey can exceed one year, and the cost associated with acquiring and processing a full 3D monitor seismic survey may be upwards of twenty million U.S. dollars. The delay in time required for a full 3D monitor seismic survey can result in missed opportunities for affecting reservoir management decisions. And, the cost of the seismic survey may exceed the benefits of the information that results from the seismic survey. Consequently, reducing the time and the cost of time-lapse seismic surveys has been an ongoing industry objective.
One approach that has been proposed for reducing the time and cost of time-lapse surveys is to permanently install an array of seismic receivers over the reservoir. See e.g., Barkved, O. I., K. Buer, and T. G. Kristiansen, 2005, Valhall Permanent Seismic Monitoring—Reducing Geological Model Uncertainties Using 4-D Seismic, EAGE 2005 Expanded Abstract. Once the receivers are in place, repeated seismic surveys can be acquired at relatively low cost by activating appropriate seismic sources over the receivers. However, although the cost of a repeat survey is lowered in this approach, the initial cost of installing the receiver array in the first place is undesirably high. Full permanent installations are generally economically advantageous when the field is small and shallow (so it can be covered without having to use a large number of receivers), and when the field has a long production life (so the cost of the installation can be spread over many monitor surveys). Because they are appropriate under a limited set of conditions, full permanent installations are rarely used.
A second approach is simply to record less seismic data in monitor surveys, thereby attempting to reduce cost and/or time involved with performing the monitor surveys. This approach has been tested with permanent (see Smit, F., M. Ligtendag, P. Wills, and R. Calvert, 2006, Toward Affordable Permanent Seismic Reservoir Monitoring Using the Sparse OBC Concept, The Leading Edge) and redeployable (see Ceragioli, E., A. Kabbej, A. Gonzalez Carballo, and D. Martin, 2006, Filling the Gap—Integrating Nodes and Streamer Data for Geophysical Monitoring Purposes, EAGE 2006 Expanded Abstract) sea-bottom receivers, and with short marine streamers (see Kaldy, W. J., K. Hartman, P. Sen, C. Barousse, D. Stauber, and E. Xu, 2006, Short cable 4D investigation—Case History from the Amberjack Field in the Gulf of Mexico, SEG 2006 Expanded Abstract). These tests indicate that 3D seismic images generated from a limited seismic data set were contaminated with levels of non-repeatable noise and imaging artifacts that were too high for most time-lapse applications.
One way to avoid artifacts that arise from conventional 3D imaging is by not performing 3D imaging. Time-lapse 2D imaging, as reported by Staples, R, J. Stammeijer, S. Jones, J. Brain, F. Smit, and P. Hatchell, 2006, Time-Lapse (4D) Seismic Monitoring—Expanding Applications, CSEG Expanded Abstract, is faster and cheaper than 3D imaging, and a 2D image does not contain the same kind of artifacts as a reduced-data 3D image. However, 2D imaging has its own shortcomings that make it inappropriate for time-lapse surveys, except in special circumstances. For instance, such 2D imaging assumes that the subsurface variations take place in the direction of the 2D line. This assumption is generally not satisfied in the actual subsurface region being targeted, so a 2D image is always a distorted version of the true subsurface.
Other methods that do not use 3D imaging are time-lapse refraction (see Landrø, M., A. K. Nguyen, and H. Mehdizadeh, 2004, Time-Lapse Refraction Seismic—A Tool for Monitoring Carbonate Fields, SEG 2004 Expanded Abstract), and time-lapse vertical seismic profile (VSP) (see Landrø, M., P. Digranes, and L. K. Strønen, 2006, Pressure Depletion Measured by Time-Lapse VSP, The Leading Edge, 24, 1226), but these are also useful only under special circumstances.